Patent Application
20100051267
This invention relates to gas wells and more particularly, to methods and systems for removing liquids from gas producing wells.
Wells that produce gas and have concurrent production of liquids such as water, oil or condensates, are often incapable of clearing these liquids from the well bore. This is especially true in depleted reservoirs and low-rate gas wells. Liquids accumulate in the well bore as gas is produced. Accumulated liquid exerts backpressure on the producing formation such that flow of gas is reduced or completely restricted.
Existing technology for dewatering of gas wells can be divided into two general categories: high cost and low cost. For the purposes of this specification the term dewatering encompasses the removal of liquids including but not limited to water.
Typical high cost dewatering methods for reducing liquid accumulation in the well bore and reestablishing a viable gas production rate usually involve external energy sources to power a pumping technology such as down-hole pumps. One problem with external energy sources such as down-hole pumps is that many pumping methods are labor intensive, require regular attention and generally use expensive equipment to provide an external source of lifting capacity to clear the well bore of the liquids. As a result, these technologies are cost prohibitive, and are often not economically viable for low production wells.
Low cost dewatering technologies have a narrow operating range, and must be suited to each individual well based on well characteristics such as water gas ratio (WGR), well pressure, and gas flow rate. This information is often unavailable, and can be highly variable over time. Low cost technologies generally require regular attention from operations staff which can be problematic in areas of limited or restricted lease access. The narrow operating range of low cost dewatering technologies means that they usually fail when well conditions change in such a way that they are outside of the operating range. Failure of these technologies results in down time and lost production, and can also require attention from operations staff in order to resume production.
A need therefore exists for a well dewatering method and system that overcomes at least one of the above mentioned shortcomings associated with existing technologies or at least overcomes one shortcoming inherent to existing and potential well dewatering systems further to those described above.
A gas flow system for removing a liquid from a gas well bore and allowing for gas production and a method of dewatering a gas well while allowing for gas production are provided. The gas flow system switches between various production phases based on the conditions of the gas well to ensure that liquid build up is reduced or prevented while gas flow is maintained. The production phase may be selected based on the determined influx rate of liquid in addition to comparing a tubing critical velocity of a tubing string of the system and a flow rate through the tubing string. In one embodiment, when the flow rate through the tubing string decreases below a preset threshold, for example the tubing critical velocity, the system automatically switches from a current product phase to an alternate production phase more suitable for effecting dewatering of the gas well bore and allowing for gas production. Switching of the current production phase to the alternate production phase may be based on different measured and calculated conditions or a combination of measured and calculated conditions of the gas well. An Evaluation Mode may be used to determine the well conditions such as rate of liquid influx.
In one illustrative embodiment, there is provided a gas flow system for removing a liquid from a well bore and allowing for gas production, the system comprising:
In another illustrative embodiment, there is provided a method of dewatering a gas well while allowing for gas production, the gas well comprising:
A programmable logic controller (PLC) 180 may be used to process the measurements taken from the pressure measurement devices and the flow meters and for controlling the tubing control valve 166 and the casing control valve 154 based on predetermined criteria as will be discussed in more detail further below. The PLC 180 may continuously evaluate well conditions and select from one of a number of production phases, which suits the evaluated well conditions.
The gas flow system 100 uses and implements a number of production phases based on the conditions of the gas well and switches between phases as conditions in the gas well changes thereby allowing for gas production and dewatering of the gas well without the need for substitution or addition of components during operation. This ability to switch between production phases based on the conditions of the gas well results in the minimizing and even elimination of downtime due to liquid accumulation in the gas well, minimization of attention by operations staff after installation and setup, and the avoidance of high cost external power source equipment such as down-hole pumps.
The system 100 uses an Evaluation mode that determines the rate of liquid influx. Based on the determined rate of liquid influx together with gas production conditions, the system 100 can move between various production phases that provide for water removal and gas production that are more suited to the current gas well conditions, thereby providing a wider operating range than each production phase provides individually. This is beneficial as the rate of liquid influx changes over time as does the gas production rate. More efficient gas production is achieved when the backpressure on the well is minimized.
The production phases include but are not limited to:
Phase 1) Casing flow with auto cleanout;
Each of these production phases will be discussed in more detail below.
By providing a system 100 that integrates at least two of the production phases, the system is able to provide extended well life and increased gas production for liquid loaded wells. The system is particularly applicable for shallow and coal bed methane (CBM) wells that produce low and moderate volumes of water that restrict production by increasing sand face pressure, as these wells typically require less energy and the system 100 typically runs on reservoir energy. The system 100 can also be used in deeper, high liquid production, and high productivity wells.
A suitable production phase may be determined based on the gas and water influx rates and a critical rate. The tubing string 120 set in the well bore is used to transfer down hole pressure and the associated water level to the surface. By using the change in the pressure difference over time between the tubing surface pressure and the casing surface pressure, the rate of water influx can be determined and a desirable or suitable production phase that will provide ideal or suitable gas production may be selected.
One example of a method of determining the rate of influx in the Evaluation Mode is as follows. The well bore is cleaned out by opening the tubing control valve 166 and closing the casing control valve 154. This will flush any liquid that is in the well bore out until the liquid level is at the tubing-liquid interface. The tubing control valve 166 is then shut. The static gas column in the tubing 120 will then provide the downhole tubing pressure. This downhole tubing pressure is quantified by a tubing pressure measurement device 162 plus the gas gradient, where the gas gradient, as is known in the industry, is a measure of the pressure exerted by the column of gas in the well bore and is commonly measured in kPa/m. As a result, for example, for every meter moved down in the well bore, the pressure increases by 0.57 kPa. Then, the casing control valve 154 is opened and allows gas to be produced up the well annulus into the casing flow line 150. If there is water influx into the well bore, the differential liquid head 140 will increase. The result is a direct increase in the tubing surface pressure. The change in the pressure difference between the tubing 120 and the casing 110 over time will provide the rate of liquid influx. The liquid influx rate is determined by calculating the column of liquid corresponding to the observed differential pressure (Tubing Pressure—Casing Pressure) multiplied by the annular cross-sectional area between the CID and the TED and then divided by the lapse of time when the incremental pressure occurred. A general formula for calculating the rate of liquid influx is:
where:
The critical rate is a parameter that defines transitions between the production phases. It may be defined as the minimum gas flow rate required to suspend a droplet of liquid (water and/or condensate for example) in a stream of gas. This condition occurs when the drag force of the gas flowing upwards balances out the force of gravity acting downwards on the droplet of liquid. Any additional gas will force the droplet of liquid to travel upwards along with the stream of gas thereby minimizing the liquid that accumulates in the well bore to cause liquid loading.
The objective of the system 100 is to keep the well from loading with liquids, while achieving or increasing gas production. Maintaining critical gas flow rate will ensure that the well does not load with liquids. Gas production may be maximized by implementing the production phase of Casing flow, Slipstreaming, or Tubing flow if the gas flow rate is greater than the critical rate. Conversely, if the well is flowing below the critical rate, a liquid loading condition will prevail, and the Switching valves production phase may be implemented to unload the liquid from the well.
The results of the water influx determination and the critical flow rate may be used to determine the suitable production phase for the gas well. In this way, the system 100 including the PLC 180 may monitor and select the most suitable production phase for the well without input from operations staff.
The four main production phases will now be discussed in more detail.
Phase 1) Casing Flow with Auto Cleanout
Casing flow is the conventional method for producing gas from a gas well. The gas is allowed to flow up the annulus of the production casing 110. When operating in the casing flow production phase, one of two optional sub-phases may be selected. The first sub-phase is selected when the gas well has sufficient pressure and flow rate to naturally lift any produced liquids to the surface. The second sub-phase occurs when liquid accumulates at the bottom of the gas well while the well is producing up the casing 110 at a controlled rate. The system 100 monitors the differential pressure between the casing 110 and the tubing 120 and can alleviate this problem. When the differential pressure reaches a preset limit, liquid flow may be diverted to the tubing 120 to flush the built up liquid from the wellbore to increase gas production.
This production phase is applicable to gas wells having conditions with low liquid influx and high gas production rates. The gas is allowed to flow up the casing 110 while liquids accumulate in the wellbore. The benefit of this production phase is reduced frictional pressure losses compared to when the gas is flowing up the tubing 120. The larger cross sectional area of the casing 110 reduces the gas velocity and in turn reduces the frictional pressure loss.
The preset limit may be determined initially by empirical correlation and may be tuned to the optimum well response by reviewing the operating performance and production flow volumes.
Slipstreaming is a technique that maintains critical velocity in the tubing by choking the casing gas flow in the annulus allowing both gas and entrained liquid to be produced up the tubing 120, and gas to flow up the casing 110. The tubing flow meter 164 in the tubing 120 and the casing gas flow meter 156 will calculate the gas velocity through the cross-section areas. The PLC 180 is set to keep the gas velocity higher than the Turner critical velocity, also referred to as the critical velocity, in the tubing.
An illustrative sequence of events occurring with this production phase is described:
1) The total gas stream is allowed to flow through the tubing 120. The critical velocity for the tubing 120 is evaluated and the valves 166 and 154 are controlled to maintain the tubing flow such that the gas velocity is at or above the critical velocity. This may be monitored and controlled by the PLC 180.
2) When the tubing flow approaches critical velocity, the casing valve 154 is opened to divert a portion of the total flow to the annulus until the tubing flow is just above the Turner critical velocity. This procedure may be automatically executed by the PLC 180 that takes the information from the flow meters 156 and 164 and activates the casing control valve 154 on the casing side to control the flow through the casing 110.
3) If the tubing flow drops below critical velocity, the casing stream is pinched out until the casing 110 is fully closed and all of the gas flows through the tubing 120. The cycle will then repeat.
4) The well will keep the water out of the hole as long as the tubing gas velocity remains higher than the critical velocity.
If the liquid is not being effectively removed from the well bore, the tubing flow will decrease and additional back pressure is applied to the casing by closing the casing valve 154. The PLC 180 may automatically attempt to optimize the gas well in this mode by gradually opening the casing valve 154 until the stabilized tubing flow is achieved with the lowest casing back pressure.
Ideal gas production with continuous liquid unloading from the gas well can be maintained and intermittent flow regimes that are associated with liquid loading in the well bore may be avoided. Initial set points may be established with empirical correlations that can be determined using evaluation phase data. The critical velocity set point can be established by a Turner correlation. An example of the correlation is shown below
Gas production from tubing and casing pressure should be monitored when using the Slipstream Valve System production phase. Critical velocities for all cross-section areas, including annulus and tubing velocities should be determined to define the proper tubing diameter for a given casing diameter. The installed tubing diameter should be defined with the current and anticipated gas production and liquid production rate. The tubing is designed to unload the maximum projected liquid volume for a given volume of gas.
When the gas well is operating in a stable slipstreaming mode, the PLC 180 will attempt to self-optimize from initial set parameters by reducing casing back pressure until the tubing velocity drops below the critical velocity. To determine if the water influx rate changes as the well is produced, the PLC 180 may measure the influx rate, using the method for example as outlined above, on a periodic basis.
A variation of this technique using a differential pressure controller on the casing control valve 154 that will control the tubing critical velocity may alternatively be implemented. The differential pressure controller will provide a lower cost system that will not automatically optimize for changes in flow condition. Manual intervention is required to tune the differential controller as it does not provide a complete measurement of tubing critical velocity. This will partially bypass the PLC 180 for the slipstream control, but the Evaluation mode and casing flow data may still be used to determine if slipstreaming is the optimum production phase of the well based on the current conditions.
As the well depletes, the bottom hole pressure will decrease and the slipstreaming controls will automatically close the casing valve until all of the gas flow is routed into the tubing 120.
Some features of utilizing a slipstream production phase are:
1. Extended flow envelope provided by a small siphon string as only one siphon string size is required through the total life of the gas well. A variation in gas velocity is achieved when the flowing cross-section area is reduced by changing the tubing diameter for a smaller one by gradually closing the casing valve until all gas is forced to flow through the tubing 120.
2. Reduced operating sandface pressure when compared to conventional velocity string sizing. This is because a high quality performance of small diameter tubing (such as siphon strings) occurs when the gas is flowing at a velocity close to the Turner critical velocity. At gas rates lower than the critical velocity, elongated bubbles of gas (Taylor Bubbles) form and travel with the liquids to the surface in a slug flow regime. The longer the bubbles, the lower the hydrostatic pressure applied to the sandface, and the better the gas well performs. Increasing gas rates will cause the bubble to occupy the entire length of the tubing until critical velocity is reached and the water flows as droplets. Further increasing the velocity beyond the critical rate causes increasing frictional pressure losses which lessen the performance of the tubing string as outlined in the graph of
3. Low frictional pressure losses when flowing up the casing. Since a small diameter tubing 120 is used to unload the liquid from the gas well and the rest of the available gas is produced up the annulus of the casing 110, the gas suffers minimal friction pressure losses. The fluid flow in the annulus is generally considered to be single phase flow (gas only) meaning that, in a vertical well, the effect of friction will be determined by the velocity of the flow. The larger cross sectional area of the annulus means that the velocity of the gas is low (Gas velocity equals gas flow rate divided by cross sectional area, meaning high cross sectional area gives low velocity), and thus the frictional pressure losses are low compared to tubing flow. For example, gas wells that are flowing at two times the critical gas rate are candidates for slipstreaming. High permeability formations with high productive indices are more likely to succeed with slipstreaming. However, the system 100 operating in the slipstream production phase has been successfully tested in fractured formation gas wells where the permeability is low.
When the gas well has depleted to the point where slipstreaming is no longer viable, the system 100 may initiate the siphon string production phase and direct all flow of the liquids up the tubing 120 by default. In the siphon string production phase the casing valve is completely closed and all the gas is flowing up the production tubing 120. The gas well may remain in this mode until the flow velocity increases or decreases outside a specified range, in which case the system 100 may switch to slipstreaming or switching valves mode, respectively.
As the well is produced, a periodic Evaluation mode and/or casing flow test may be performed to determine if the liquid influx rate has changed and if there is a new more suitable production phase for the gas well based on the current conditions.
Continued depletion of the gas reservoir will cause the gas flow rate to drop below the critical velocity and the well will load with liquid. Optionally, the switching valves production phase may begin when this happens.
Switching valves is an existing technology and comprises operating the tubing control valve 166 and the casing control valve 154 in an intermittent manner. An illustrative cycle is described as follows:
1. Equalization: A well under liquid loading condition will show a high casing and low tubing pressures. The first step in dewatering and providing for gas production is to equalize pressures in the tubing 120 and the casing 110 by opening a valve that communicates the casing 110 with the tubing 120. This will allow the column of liquid in the tubing 120 and the annulus of the casing 110 to be a the same level.
2. Unloading the gas well: Once the pressures are stabilized, the tubing 120 is opened to production. An instantaneous expansion of the gas in the tubing 120 and annulus 110 generates enough kinetic energy to move the column of liquid to the surface. The gas pushing and carrying the liquid is produced until the pressure is released and the gas velocity nears the critical value.
3. Shut in the well: Once the gas has been produced, the gas well is shut in again and the pressure is allowed to build up in the annulus and the process is repeated.
Some limitations of the Switching valves production phase are the liquid influx from the formation and the gas productivity. A delicate balance between gas pressure build up and liquid accumulation can be achieved in order for this technology to be successful. High gas to liquid ratios are preferable.
In this example the small siphon string diameter created a restricted flow. Once the slipstreaming system was installed the well was able to produce through the casing an additional 16 MCFD of gas. The new flow condition stabilized at 79 MCFD approx. In this case the critical velocity set for the 0.7″ ID tubing was 45 MCFD. The rest of the gas was flowing through the annulus.
This technology ended up producing the total amount of gas only through the tubing once the gas production reached the critical velocity value associated with the 0.7″ ID tubing size (45 MCFD). The siphon string flow will eventually be transformed to intermittent flow as illustrated in the next example.
A description of these two methods is given in the book: Lea, J; Nickens, H; Wells, M: “Gas Well Deliquification”. Elsevier, Burlington, Mass. 2003. p. 279-281, incorporated herein by reference.
In an alternative embodiment, following step 220, the method may return to step 210 where the comparison between the evaluated flow rate and the calculated critical flow rate is carried out again. If the evaluated flow rate is greater than the critical rate, phase 3, as outlined above, is initiated in step 230.
While in phase 3, flow rate is evaluated, the pressures are measured and slugging behaviour is evaluated at step 240 to determine if the well is experiencing slug flow at step 250. Slug flow may be determined based on the average flow rate. For example, a 6 hour time interval where the slug flow evaluation is performed is discretized (broken up into smaller discrete time intervals of, for example 15 minutes). A 1 hour average of the peaks of the discrete time intervals is compared to the 6 hour average. If the average of these peaks is greater than 15% above the 6 hour average production, then slug flow can be assumed. The same is done with the low production values of the discrete time intervals. If the well is experiencing slug flow, the evaluated flow rate also referred to as gas rate is compared against a predetermined factor Y multiplied by the critical rate at step 260. If the gas rate is greater than Y multiplied by the critical rate, phase 2 slipstreaming, as outlined above, is initiated at step 300. If the gas rate is less than Y multiplied by the critical rate, phase 4 switching valves, as outlined above, is initiated at step 270. Once in either phase 2 or phase 4, the flow conditions of the well are monitored, in steps 310 and 280 respectively, and the current well conditions are evaluated to determine if a better phase for increased flow is available and the method returns to step 230. Optionally, after certain periods of time in phase 1, 2, or 4 the method, may automatically switch back to phase 3 and re-evaluate the well to determine a more suitable phase may be used. This switch back may be controlled by the PLC.
If slug flow is not occurring, as determined at step 250, the gas rate is compared against another predetermined factor Z (which typically differs from predetermined factor Y, but may be the same) multiplied by the critical rate at step 290. If the current gas rate is less than Z multiplied by the critical rate, method returns to step 260 where the current gas rate is compared against Y multiplied by the critical rate as outlined above. If the gas rate is greater than Z multiplied by the critical rate, the water gas ratio (WGR) is evaluated at step 320. At step 330, the WGR is compared to a predetermined WGR value, and if the WGR is below the predetermined WGR value, phase 1 casing flow with auto cleanout is initiated at step 340. If the WGR is not below the predetermined WGR value at step 330, phase 2 slipstreaming is initiated at step 300. Once in either phase 2 or phase 1, the flow conditions of the well are monitored, in steps 310 and 350 respectively, and the current well conditions are evaluated to determine if a better phase for increased flow is available and the method returns to step 230.
The WGR should be within a certain range so that the gas has enough energy to lift the water. If there is too much liquid for a given amount of gas, the gas will be unable to lift the water. If there is a large amount of gas, and not a lot of water (the favourable situation) the well will likely flow in phase 1 and produce the maximum amount of gas. A non-limiting example of a predetermined WGR value is 10. The WGR may be selected from possible WGR values of from about 5 to about 35 bbl/mmcf (barrels of liquid per million cubic feet of gas).
Y may be determined based on empirical (observed) data. A non-limiting example of a value for Y is 1 or 1.5. Z is related to the geometry of the well (casing and tubing size), but the specific value may be from empirical data. A non-limiting example of a value for Z is 2. The values for Y and Z may be between 1 and 2, but may also be outside of this range if the given gas well requires such a range.
As outlined above with reference to
It is not essential to have a system or method that uses all four phases to achieve increased gas production in each well. As such, one skilled in the art will appreciate that the method may simply include any two or three phases as outlined above and may involve switching between 2 or more of the production phases described herein or another suitable production phase.
The present invention has been described with regard to a plurality of illustrative embodiments. However, it will be apparent to persons skilled in the art that a number of variations and modifications can be made without departing from the scope of the invention as defined in the claims.
